1. Field of the Invention
The invention relates generally to earth-boring drill bits used to drill a borehole for the ultimate recovery of oil, gas, or minerals. More particularly, the invention relates to drag bits and to an improved cutting structure for such bits. Still more particularly, the present invention relates to arrangements of cutter elements on drag bits exhibiting decreasing degrees of cutter redundancy moving radially outward towards gage.
2. Background of the Invention
An earth-boring drill bit is typically mounted on the lower end of a drill string and is rotated by rotating the drill string at the surface or by actuation of downhole motors or turbines, or by both methods. With weight applied to the drill string, the rotating drill bit engages the earthen formation and proceeds to form a borehole along a predetermined path toward a target zone. The borehole thus created will have a diameter generally equal to the diameter or “gage” of the drill bit.
Many different types of drill bits and cutting structures for bits have been developed and found useful in drilling such boreholes. Two predominate types of drill bits are roller cone bits and fixed cutter bits, also known as rotary drag bits. Some fixed cutter bit designs include primary blades, secondary blades, and sometimes even tertiary blades, angularly spaced about the bit face, where the primary blades are generally longer and start at locations closer to the bit's rotating axis. The blades generally project radially outward along the bit body and form flow channels there between. In addition, cutter elements are often grouped and mounted on several blades. The configuration or layout of the cutter elements on the blades may vary widely, depending on a number of factors. One of these factors is the formation itself, as different cutter element layouts engage and cut the various strata with differing results and effectiveness.
The cutter elements disposed on the several blades of a fixed cutter bit are typically formed of extremely hard materials and include a layer of polycrystalline diamond (“PD”) material. In the typical fixed cutter bit, each cutter element or assembly comprises an elongate and generally cylindrical support member which is received and secured in a pocket formed in the surface of one of the several blades. In addition, each cutter element typically has a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide (meaning a tungsten carbide material having a wear-resistance that is greater than the wear-resistance of the material forming the substrate) as well as mixtures or combinations of these materials. The cutting layer is exposed on one end of its support member, which is typically formed of tungsten carbide. For convenience, as used herein, reference to “PDC bit” or “PDC cutter element” refers to a fixed cutter bit or cutting element employing a hard cutting layer of polycrystalline diamond or other superabrasive material such as cubic boron nitride, thermally stable diamond, polycrystalline cubic boron nitride, or ultrahard tungsten carbide.
While the bit is rotated, drilling fluid is pumped through the drill string and directed out of the face of the drill bit. The fixed cutter bit typically includes nozzles or fixed ports spaced about the bit face that serve to inject drilling fluid into the flow passageways between the several blades. The flowing fluid performs several important functions. The fluid removes formation cuttings from the bit's cutting structure. Otherwise, accumulation of formation materials on the cutting structure may reduce or prevent the penetration of the cutting structure into the formation. In addition, the fluid removes cut formation materials from the bottom of the hole. Failure to remove formation materials from the bottom of the hole may result in subsequent passes by cutting structure to re-cut the same materials, thereby reducing the effective cutting rate and potentially increasing wear on the cutting surfaces. The drilling fluid and cuttings removed from the bit face and from the bottom of the hole are forced from the bottom of the borehole to the surface through the annulus that exists between the drill string and the borehole sidewall. Further, the fluid removes heat, caused by contact with the formation, from the cutter elements in order to prolong cutter element life. Thus, the number and placement of drilling fluid nozzles, and the resulting flow of drilling fluid, may significantly impact the performance of the drill bit.
Without regard to the type of bit, the cost of drilling a borehole for recovery of hydrocarbons may be very high, and is proportional to the length of time it takes to drill to the desired depth and location. The time required to drill the well, in turn, is greatly affected by the number of times the drill bit must be changed before reaching the targeted formation. This is the case because each time the bit is changed, the entire string of drill pipe, which may be miles long, must be retrieved from the borehole, section by section. Once the drill string has been retrieved and the new bit installed, the bit must be lowered to the bottom of the borehole on the drill string, which again must be constructed section by section. As is thus obvious, this process, known as a “trip” of the drill string, requires considerable time, effort and expense. Accordingly, it is desirable to employ drill bits which will drill faster and longer, and which are usable over a wider range of formation hardness.
The length of time that a drill bit may be employed before it must be changed depends upon a variety of factors. These factors include the bit's rate of penetration (“ROP”), as well as its durability or ability to maintain a high or acceptable ROP.
Moving radially outward from the rotational axis of a PDC bit, the bit face may generally be divided into a radially innermost cone region, a radially outermost gage region, and a shoulder region radially disposed between the cone region and the gage region. Cutter elements in the cone and shoulder regions primarily cut the borehole bottom, while the cutter elements in the gage region primarily ream the borehole sidewall. Due to space constraints, the number of cutter elements in a given region of the bit face typically increases moving radially outward. For instance, the number of cutter elements in the shoulder region is usually greater than the number of cutter elements in the cone region. For a given weight-on-bit (WOB), the fewer the cutter elements in a given region, the greater the cutting force on each cutter element in the region, and hence, the greater the depth-of-cut (DOC) of such cutter elements (the greater the cutting force on a given cutter element, the greater the DOC of the cutter element).
In many conventional PDC bits, the relatively few cutter elements in the cone region are each disposed at a unique radial position relative to the bit axis, and thus, no two cutter elements in the cone region are disposed at the same radial position relative to the bit axis. WOB is shared and divided among cutter elements at unique radial positions, leading to reduced cutting forces, and hence, reduced DOC, for each cutter element disposed at a unique radial position. Preferably, the WOB is sufficient to enable each cutter element to exert a cutting force on the formation that exceeds the rock strength, thereby enabling the cutter elements to positively engage and shear the formation. However, in some cases, an insufficient WOB may result from low rig capacity, concerns over bit deviation under excessive WOB, concerns over perceived cutter element breakage, etc. In such cases, cutter elements disposed at unique radial positions exert further reduced cutting forces on the formation, and therefore, provide a reduced DOC. As a result, such cutter elements may not engage or bite the formation sufficiently to shear the formation, but rather, may tend to grind the formation. Such grinding of cutter elements under insufficient WOB can lead to bit vibrations and associated instability, reduced bit durability, and reduced ROP, particularly in harder formations.
Accordingly, there remains a need in the art for a fixed cutter bit and cutting structure capable of enhancing bit stability, bit ROP, and bit durability. Such a fixed cutter bit would be particularly well received if it offered the potential for enhanced cutting forces for each cutter element and enhanced DOC for each cutter element at a given WOB.